1. Field of the Invention
This invention pertains to recovery of crude oil from subterranean reservoirs by injecting both water and a second less dense fluid to displace the oil, preferably through horizontal wells. The invention is based on the proper selection of spacing and relative location of injection and production wells, and proper selection of injection rates and location of injection completion intervals for both water and the second fluid.
2. Description of the Related Art
Although gas efficiently displaces oil in a vertical downward displacement that is aided by gravity, gas displacement of oil by predominantly horizontal flow is inefficient because of the low viscosity of the gas relative to the oil. The gas fingers through the oil, giving poor conformance and resulting in a low recovery of the oil. Injecting water along with the gas was proposed to control this fingering and poor conformance. The water decreases the mobility of the gas by lowering the relative permeability of the formation to the gas. Field tests showed it was most feasible to inject the water alternately with the gas. This process is known as WAG flooding. The ratio of the volume of water injected to the volume of gas injected is the WAG ratio. Injection of any second fluid, not just gas, alternately with water is now termed WAG flooding. Much of the literature on WAG flooding has centered on the use of water and miscible or nearly miscible fluids that reduce the residual oil after flooding to a value near zero. However, immiscible gases may also provide a substantial beneficial lowering of the residual oil. Thus if miscible gas is not available, or is too expensive to use, then immiscible gases should be considered the WAG flooding.
The literature on this lowering of the residual oil by the presence of an immiscible gas is briefly reviewed here. The reduction of resident oil below that of a water flood is expressed here and in the literature as a fraction of the gas trapped at the end of the flood. In evaluated these data, it is important to remember that although different authors may use the same term like “weakly water-wet” to describe their samples, it is unlikely that their sample wettability conditions are identical. Such terms are not precisely defined nor controlled in experiments; these terms are qualitative, rather than quantitative.
Skauge (1994) (Skauge, A., 1996, “Influence of Wettability on Trapped Nonwetting Phase Saturation in Three-phase Flow,” Proceedings 4th International Symposium on Wettability and Its' Effect on Oil Recovery, Montpellier, France, Sept.) reports a fraction ranging from 0.5 to 1.0 for water wet systems and 1 for weakly water wet systems. For the systems with a fraction of 1.0, immiscible gas displacement is essentially as effective as miscible gas, and, being cheaper, will be more attractive economically. Other investigators did not find fractions as high as Skauge, McAllister et al., 1993, reported fractions of 0.75, 0.25 and 0.4 for water wet, mixed-wet and oil-wet conditions, respectively. Their core samples were Baker dolomite. For water-wet systems, Holmgren and Morse, 1951, and Kyte et al., 1956, suggest that this fraction is roughly 0.5. Kralik et al., 1996, gave previously unpublished data from the 1950s of 0.59±0.09, 0.51±0.08 and 0.45±0.08 for water-wet, weakly water-wet and intermediate-wet samples. Kyte et al. also reported a fraction of zero for an oil wet system, as did Kralik et al. When this fraction is zero, immiscible WAG does not result in additional recovery above water flood and so should not be used.
Salathiel in 1973 (Salathiel, R. A. 1973 “Oil Recovery by Surface Film Drainage in Mixed-Wettability Rocks,” JPT Oct. pp. 1216-1224.) postulated a likely way that reservoirs could become mixed-wet during oil accumulation over geologic time and simulated it in laboratory experiments. He also reviewed literature data, much of which supports the view that most reservoirs would be expected to be “mixed-wet”, “weakly water-wet” or “intermediate-wet”, using the various terms applied by the above authors.
Although there is appreciable variation in the above fractional reduction data, the preponderance shows fractions in the 0.5-1.0 range, except for the rarely encountered strongly oil-wet systems. This range is high enough to mandate investigation of the effectiveness of immiscible gases for specific field and fluid systems, rather than assuming that miscible WAG flooding is always most economic.
Gas phase tracers, though not essential, can be very helpful in monitoring and controlling WAG floods. Yang, et al., 2000, (“Tracer Technology for Water-Alternating-Gas Miscible Flooding in Pubei Oil Field”) report a series of perfluorocarbons that they found useful for this purpose. Yang and Zhang, 1999, present methods for detecting and analyzing for these perfluorocarbons.
Oil recovery by WAG flooding has been limited by gravity segregation of the gas and water. Gravity segregation is not limited to WAG flooding, but occurs in all flooding processes. Gravity segregation in a typical water flood is described in U.S. Pat. No. 3,565,175 issued to Wilson on Feb. 23, 1971. In a WAG flood, gravity causes the gas to rise to the top of the reservoir and water to migrate to the bottom. After segregation is complete, a miscible flood occurs in a thin layer at the top of the reservoir. The remainder of the reservoir is only water flooded. Various methods have been proposed to control or reduce gravity segregation in WAG floods and various other water and miscible flooding methods. For example, Wilson (3,565,175 February 1971 Wilson 166/269) describes a method for reducing gravity segregation of an aqueous flooding fluid in a reservoir containing fluids of a lower density than the aqueous flooding fluid. That method calls for adjusting the viscosity of the aqueous flooding fluid injected into progressively lower levels of the reservoir. This adjustment is said to decrease the mobility of the fluid sufficiently to offset the additional pressure exerted at the lower levels by the higher density aqueous flooding fluid. The pressures are more nearly equal at all levels, tending to improve conformance. Another example is U.S. Pat. No. 3,661,208 to Scott et al, issued May 9, 1972. That patent describes a method for controlling gravity segregation in a miscible gas flood process by maintaining the reservoir at such a pressure that the miscible fluid has a density essentially the same as that of the reservoir oil. Yet another example is U.S. Pat. No. 4,427,067 to Stone, issued Jan. 24, 1984. That patent describes a WAG flood design using sufficiently close well spacing and high enough injection rates so inhibit, but not to eliminate, gravity segregation, Huang et al., in U.S. Pat. No. 5,320,170 issued Jun. 14, 1994, propose using a combination of horizontal and vertical wells to counteract gravity, and claim a modest improvement in recovery by doing so. Stevens et al. in U.S. Pat. No. 5,634,520, issued Jun. 3, 1997, claimed the use of short gas injection cycles to increase recovery, by achieving a more uniform vertical distribution of the gas injected. McGuire et al. in 1999 noted that the WAG flood at Prudhoe Bay is strongly gravity dominated, and the MI (i.e.—second fluid) sweeps oil near the injection well, but gravity segregation causes it to leave large areas of the reservoir unaffected. They proposed the use of both vertical & horizontal wells to inject the second fluid low in the formation in order to make gravity segregation take place over a greater distance, and therefore to require more time to occur. This increased time results in greater second fluid penetration into low levels of the formation, and hence greater oil recovery. Their test of a vertical well for this purpose did not give very favorable results. Drilling horizontal wells near the bottom of the formation for alternate water and MI injection worded better. They concluded that in a gravity dominated reservoir like Prudhoe Bay, this approach appears to be economically competitive with WAG flooding as proposed by Stone, see above. Both Edwards et al. in 2000 and Redman in 2002 confirmed the beneficial effect of such horizontal injection wells.
However, gravity segregation remains a problem in WAG flooding. The various methods proposed to control or reduce gravity segregation are often not economically feasible. They are expensive processes in themselves and/or they do not result in enough oil recovery to make the profitable. Other such methods are successful only in certain types of reservoirs or under certain reservoir conditions. Usually such methods, while appropriate for water floods or miscible slug drives, are not useful for improving the vertical conformance of a WAG flood. Methods are needed that will yield higher vertical conformance in a WAG flood.